This disclosure relates to identifying whether a reservoir likely received two or more hydrocarbon charges based on downhole fluid properties using downhole fluid analysis.
This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present techniques, which are described and/or claimed below. This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure. Accordingly, it should be understood that these statements are to be read in this light, and not as admissions of prior art.
A hydrocarbon reservoir in a geological formation gradually forms over geologic time. An oil source rock, located in a basin, produces hydrocarbons, which migrate into a reservoir. In a normal time sequence of basin subsidence, the oil source rock initially generates heavier, less mature hydrocarbons with lower gas-oil ratio (GOR) and higher asphaltene content. At later times, with greater subsidence and high temperatures for longer times, the source rock generates lighter, more mature hydrocarbons. In some cases, a reservoir will contain predominantly a narrow range of maturities, while in other cases, the reservoir will contain a mixture of different maturity hydrocarbons.
The properties of the formation fluid have a substantial impact on well development and production. Asphaltene onset pressure (AOP), for example, describes a relationship between temperatures and pressures of the formation fluid at which the formation fluid begins to precipitate asphaltene components. During well development or production, it may be possible for the formation fluid to reach temperatures and pressures that cross the AOP envelope. When this happens, asphaltenes may begin to precipitate out of the formation fluid, which could result in a number of well-production challenges. Asphaltene precipitation can cause production-choking deposition inside tubulars and pipelines as well as a reduction in permeability of the reservoir rock. Thus, downhole tools may be used to estimate AOP of formation fluid downhole through downhole fluid analysis, or to obtain samples for testing at a laboratory at the surface.
In addition, scientists and engineers have developed complex computer models that simulate the behavior of the reservoir over geologic time. These models may be used to identify potential well-production concerns in advance. Well designers and producers may use the models to make well development and production decisions that proactively address these potential well-production concerns. There may be a very large number of possible realization scenarios that could describe the behavior of the reservoir over geologic time, however, and it may be difficult to identify which realization scenarios are most likely. The more likely the realization scenario that is used in the model, the more likely the model of the reservoir will accurately describe the behavior of the reservoir. To those involved in planning and producing the well, the accuracy of the reservoir model may impact plans for future field development plans and/or well operations, such as enhanced oil recovery, logging operations, and dynamic formation analyses.